Thursday, December 23, 2010

Many of the main energy trends of 2010 were predictable at the year's start, including the growing reliance of renewable energy on government assistance in the aftermath of the financial crisis, the debate over US greenhouse gas legislation, the emphasis on green jobs and competition with China, the delayed arrival of cellulosic biofuels, and the anticipation surrounding the product launches of the first mass-market electric vehicles. As interesting as all this was, the year in energy was dominated by two transformative events: the Deepwater Horizon accident and the multi-million barrel leak that ensued, and the less spectacular but no less profound awakening to the possibilities of the shale gas revolution.

The Deepwater Horizon disaster has been the subject of such extensive coverage and investigation that there's little I can add concerning the facts, other than to note that we have not heard the last word on just how much oil actually leaked into the Gulf of Mexico. The consequences of our response to the spill will be with us for a long time, both in terms of reduced offshore drilling activity and the decline in US oil output that must inevitably follow. The impact will reach far beyond the tens of thousands of workers whose livelihoods are directly or indirectly linked to the US offshore industry. Early in 2010 it looked like the industry would finally be offered access to areas that had been off-limits for decades, and by year-end not only has drilling in the central and western Gulf come to a near standstill, but the prospect of leases in the eastern Gulf and the mid-Atlantic coast has been foreclosed, perhaps permanently.

The psychological impact of the event could extend even farther than its physical and economic fallout. Whatever misgivings many people had about offshore drilling before the accident, the industry had built up trust through an impressive string of technical achievements--pushing the boundaries of resource accessibility from depths of a few hundred feet into nearly two miles of inhospitable ocean--and a solid reputation for safety. In the space of one day and the following weeks, that trust was shattered. Coming on the heels of a financial crisis that destroyed the trust of millions of Americans in the nation's largest financial institutions and markets likely amplified the effect. As fickle as we Americans sometimes seem, I wouldn't bet that this trust can be restored quickly, or to the same degree.

The shale gas revolution is a completely different kind of story, though it, too, has arguably been tainted by Deepwater Horizon. As it unlocks a resource that has converted the US natural gas supply outlook from one of scarcity and growing import dependence to expected abundance for decades, the gas industry can't assume it will receive the benefit of the doubt concerning the environmental impact of the drilling techniques that have made this turnabout possible.

Perhaps one reason the impact of cheap natural gas hasn't sunk in yet is that the main market price for gas, the futures price at the Henry Hub in Louisiana, doesn't have much relevance for the average consumer. Residential gas customers don't buy their gas in the million-BTU (MMBTU) lots in which the futures contract is denominated; we buy gas in therms--one tenth of an MMBTU--and by the time we see it on our bills all sorts of handling and distribution fees and mark-ups have been added on. But when you compare the price of traded gas in barrels of oil equivalent (BOE) to the price of West Texas Intermediate crude, the remarkable divergence of the last two years becomes obvious, as shown in the chart above. Between 2000 and 2006 gas and oil tracked each other closely, allowing for the greater seasonal volatility of the former. There were even periods when a barrel-equivalent of gas was worth more than a barrel of oil. Yet while oil and gas prices fell precipitously when the recession and financial crisis burst the various asset bubbles, they have diverged sharply since then, with oil advancing back up to today's $91/bbl and gas settling into the $20-25/bbl range in which we were accustomed to see oil prices a decade ago. Adjust that for inflation and you're looking at an average natural gas price for 2010 equivalent to $20/bbl in 2000.

That might help explain why the developers of renewable electricity sources such as wind have struggled so much this year, despite receiving $3.9 billion in direct cash grants from the US Treasury. They're not competing with $90 oil; the US generated less than 1% of its electricity from petroleum this year, through September. Instead, they're competing with gas at an effective price of $25/bbl or less. But if this is a new obstacle for some renewables, it surely represents a huge opportunity for the country as a whole, as we struggle to find our way out of the fiscal and competitive pit we've dug. Cheap energy has always been a key to growth, and right now, gas is the only energy source offering that without requiring an enormous up-front investment. It's no panacea, and it can't take on every burden without being spread so thin that its price advantage would disappear. But I'd much rather be looking at the possibilities this presents than at the constraints that high-priced oil and natural gas imposed only a couple of years ago.

That's probably as good a note as any on which to end the year. New postings will resume the week of January 3, 2011. In the meantime, I wish my readers a happy holiday season.

Monday, December 20, 2010

One of the energy stories I've followed with great interest all year concerns efforts to increase the proportion of ethanol blended into ordinary US gasoline. This began last year when Growth Energy, an ethanol trade association, asked the Environmental Protection Agency for a waiver to increase the allowed percentage of ethanol in gasoline from 10% to 15%. In October EPA issued a partial approval of the request, but only for vehicles built in model year 2007 or later. However, a new report from Underwriters Laboratories (UL) indirectly casts doubt, not only EPA's ruling, but on whether the agency was assessing all the relevant issues.

I ran across the UL report on the compatibility of mid-level ethanol/gasoline blends in gasoline dispensing equipment--the pumps, hoses and tanks in gas stations--in a posting on API's EnergyTomorrow blog. It cited the UL study, which had been commissioned by the Department of Energy, as evidence that E15, the 15% blend of ethanol and gasoline that the EPA just approved for use in newer cars, could result in serious failures of gas pumps. Yet when I read the report, I immediately encountered its innocuous-sounding conclusion stating, "The overall results of the program were not conclusive insofar as no clear trends in the overall performance of all equipment could be established." It went on to say that the equipment "generally performed well." If I had stopped reading there, I'd have concluded that API was blowing the whole story out of proportion.

When I read the data included in the report, however, a different story emerged. Of the new and used gasoline dispensers and associated equipment tested, very few exhibited no problems on the 17% ethanol test fuel used. In fact, in UL's long-term exposure test, many hoses, nozzles and swivels leaked. 100% of the meter, manifold and valve assemblies tested leaked or failed to shut off. Perhaps most worryingly, two-thirds of the breakaway couplings tested leaked, failed their pressure tests, or required more than the recommended pull to separate. (A breakaway is designed to pop the hose off the dispenser when a customer forgets to remove the nozzle from his car's gas intake and attempts to drive off. This happens a surprising number of times a year, and before the deployment of breakaways such incidents imposed significant repair costs on dealers, even when the resulting spills didn't cause fires.)

The common denominator in these failures was what the report refers to as "nonmetals", gaskets, seals and parts made from various polymers. From that I would draw two conclusions: First, it ought to be possible to design new dispensers and retrofit existing dispensers with new gaskets, seals and plastic parts designed to withstand higher concentrations of ethanol, just as the fuel systems in flexible fuel vehicles are designed to tolerate blends of up to 85% ethanol. However, considering that the US has between 90,000 and 160,000 gas stations, depending how you count them, the number of dispensers that would have to be modified is at least in the high tens of thousands, if not well into the hundreds of thousands. To my knowledge the ethanol industry has not offered to defray the cost of these conversions for a retail fuel industry that operates with extremely lean margins. Nor is it obvious that dealers would qualify for federal assistance, as they do when they add E85 capability.

My second conclusion--really more of a suspicion--has nothing to do with gas pumps or gas stations, and everything to do with cars. After reading the UL report I went back and reread portions of the EPA's official waiver response, which ran to 58 pages in the Federal Register. From what I can tell, EPA wasn't really looking at whether cars would suffer damage from operating on a higher percentage of ethanol than the fuel for which they were designed. The waiver was granted on the basis of those cars not emitting more pollutants than on the fuel for which they were designed. Quoting from the EPA document:

"For MY 2007 and newer light-duty motor vehicles, the DOE Catalyst Study and other information before EPA adequately demonstrates that the impact of E15 on overall emissions, including both immediate and durability related emissions, will not cause or contribute to violations of the emissions standards for these motor vehicles. Likewise, the data and information adequately show that E15 will not lead to violations of the evaporative emissions standards, so long as the fuel does not exceed a Reid Vapor Pressure (RVP) of 9.0 psi in the summertime control season. The information on materials compatibility and drivability also supports this conclusion."

That's good as far as it goes, but from my perspective this finding reflects a necessary but hardly sufficient standard for putting a new fuel into the marketplace, particularly when the failures of the dispensers in the UL study point to the possibility of similar failures of "nonmetals" in the fuel systems of cars or other devices not designed to run on more than 10% ethanol. Even if the leaks found in the testing of product dispensers didn't result in safety hazards, they would at a minimum increase the evaporative emissions from infrastructure, aside from the automotive impact on which EPA apparently focused. I also find it interesting that a bill was introduced in Congress this summer, as EPA was considering the waiver request, that would appear to make it more difficult for consumers to recover the cost of damages resulting from compatibility problems in approved vehicles or misfueling of non-approved vehicles.

As I've noted in my previous postings on this topic, I'm sympathetic to the box into which altered circumstances have placed both the ethanol industry and the federal government with regard to ethanol blending. US gasoline sales, which stagnated after the financial crisis and are only growing by a historically modest 0.7% this year (through November) according to API's latest statistics, are not expanding fast enough to accommodate the output of all the ethanol plants that have been built or are under now construction. When the Renewable Fuels Standard was enacted as part of the Energy Independence and Security Act of 2007, the bill's architects presumably expected that E85 sales would take up any slack. The fact that that hasn't happened does not justify creating a new outlet for additional ethanol in automobiles not designed to accommodate it, any more than it would justify running a new fuel through infrastructure that has been shown not to be up to the challenge. If EPA doesn't revisit the more comprehensive aspects of this question as part of its deferred decision on allowing E15 for cars made before 2007, then perhaps it's time for another government agency with a broader charter to take over this issue.

Friday, December 17, 2010

Last night the US House of Representatives passed the compromise tax bill without any amendments and by a healthy margin, though narrower than the 81-19 vote in the Senate on Wednesday. The bill now goes to the President for his signature. The provisions added after the initial negotiations between the White House and Republican leadership delivered a substantial Christmas present to the nation's renewable energy industry, including several key items on the industry's wish list: extension of the ethanol blenders' tax credit at its current rate of $0.45 per gallon; extension of the Treasury Renewable Energy Grants, which provide cash in lieu of investment tax credits; and a retroactive extension of the $1.00 per gallon biodiesel tax credit, which had lapsed at the end of 2009. However, as with many Christmas presents, the bill that will come due next year is also substantial. And the one-year extensions granted to these incentives leaves their long-term fate in the hands of the new Congress, which is widely expected to be more focused on deficit reduction than on stimulus.

This result constitutes a remarkable trifecta. As recently as a week ago it seemed likely that the Treasury Grant program would expire on schedule, and that the ethanol credit, if not actually allowed to expire, would at least be reduced to reflect its redundancy with the Renewable Fuel Standard (RFS), which requires refiners and fuel blenders to add biofuel to gasoline. As for the biodiesel tax credit, it looked like a lost cause all year, having failed on multiple previous attempts to reinstate it. The US ethanol industry even prevailed in having the $0.54 per gallon duty on imported ethanol extended for another year, in order to shield taxpayers from paying incentives to foreign producers and the industry from cheaper competition--though I'm not sure how competitive Brazilian cane ethanol really is these days, with sugar trading at around $0.30/lb ex duty. (As I understand the tradeoff, a gallon of cane ethanol consumes roughly the same raw materials as 10 lb. of cane sugar.)

It's a tribute to the greatly expanded scale of renewable energy that the price tag for the one-year extension of these three incentives is as high as it will be. This year, even with US wind turbine installations running well behind their record pace in 2009, the Treasury has spent $3.9 billion on the grant program for projects installing geothermal, solar, wind and other renewable electricity equipment. With continued strong growth in both solar thermal and photovoltaic projects and even a modest uptick in wind installations, the tab for 2011 could easily break $4 B. (A separate manufacturers tax credit, which had a better claim on creating green jobs here in the US, was not extended.) Meanwhile, with conventional ethanol and biodiesel blended at the mandated rates for next year, they should account for around $5.9B and $0.8 B, respectively. That comes to $10.7 billion for all three programs.

Although the tax compromise has extended the energy policy status quo for another year, change is in the air. With continued, though narrower bi-partisan support, the ethanol industry's argument that its tax credit is still necessary after 32 years--even with a steadily increasing RFS mandate--is losing credibility. Part of the industry would prefer this money to be spent encouraging infrastructure for E85 and other higher-percentage blends that represent ethanol's future growth opportunity, if any. As for the Treasury Grants, a temporary stimulus measure intended to make up for the disappearance of the tax equity market during the financial crisis, the defensibility of treating the investment tax credit on which it is based differently from any other credit in the tax code is waning. This mechanism looks increasingly exposed as the broader category of "tax expenditures" becomes an obvious target for deficit cutters, and the justification for extending it beyond next year would probably vanish if the Congress enacted legislation along the lines of Senator Graham's Clean Energy Standard. The industry should make the most of the current Christmas package, because the odds are against a repetition of it turning up under next year's tree.

Wednesday, December 15, 2010

With so much attention focused on the boom in natural gas from new shale resources, we shouldn't lose sight of the importance of domestic offshore gas, mainly from the Gulf of Mexico. Although it has been declining for the last decade, offshore production still accounts for about 13% of US gas output. Before the Deepwater Horizon disaster the Department of Energy expected that proportion to increase again to as much as 18% of a larger total. However, if drilling in the Gulf doesn't resume--and fairly soon--not only could that portion of our supply deplete rapidly, but its shrinkage would erase much of the incremental contribution from shale gas, a scenario depicted in the chart below. If that occurred, ambitious plans to capitalize on shale gas to displace coal or imported oil would be nullified, and gas prices would shortly revert to their previous upward trajectory.

Despite the official end of the deepwater drilling moratorium and the recent release of new guidelines to aid the industry in filing for deepwater permits, it doesn't look like drilling has resumed or is likely to do so any time soon. Meanwhile, deepwater drilling outside the US seems to be recovering rapidly. It's almost irrelevant whether the ongoing US offshore hiatus is the result of the complexity of new rules and regulations, inadequate staffing of the reorganized Bureau of Ocean Energy Management, Regulation and Enforcement, or what some believe is a tacit, unofficial moratorium on the part of the administration. Together with the recent withdrawal of plans to lease portions of the Eastern Gulf of Mexico, where significant gas resources had already been discovered, the hiatus threatens to return the US to our previous situation of increasing reliance on LNG imports, in spite of growing shale gas output.

Aside from the gas volumes and the significant number of industry and related jobs involved, there's also a fair amount of government revenue at stake in the form of forgone royalties and bid bonuses. Salazar's announcement indicated new offshore leasing wouldn't resume until late next year, at the earliest. That wipes out at least $500 million of expected bonuses--the figure for 2008 was $6.9 B--and the aggregate production decline resulting from no new drilling would lead to a steadily increasing loss of annual royalties, as existing fields deplete and aren't replaced. Between extended environmental studies, delayed permits, and areas re-designated as off-limits that were expected to be available within the 2007-12 cycle, our offshore energy supplies are looking precarious, and that will eventually influence the price we pay for energy--for both gas and imported oil. Recent polling suggests the majority of Americans understand that.

As I've noted before, no one expects things to revert to the way they were before this summer's massive oil spill. However, if we erect too many obstacles in the way of exploiting the abundant hydrocarbon resources of the Gulf of Mexico--even for natural gas, which although subject to the risk of blowouts presents little or no risk of spills like the one from the Macondo well--the costs will not just be financial; they will extend to our environment and energy security.

Monday, December 13, 2010

Saturday's conclusion of the Cancun climate talks yielded modest agreements that allowed the meeting to be described in positive terms by its hosts and organizers, but at least on the major question of a globally-binding treaty to extend or replace the expiring Kyoto Protocol, it merely kicked the can down the road to the late-2011 session in Durban, South Africa. As low as the expectations going into Cancun were, keeping the UN climate process on life support looks like a good result, compared to last year's fiasco in Copenhagen. However, in light of the objections raised by Japan, Russia, Canada and others, it's difficult to see how the Durban meeting could succeed where Cancun and Copenhagen failed. It looks increasingly likely that the replacement for Kyoto might appear face-savingly similar, but will lack that document's cohesiveness and global authority.

As I read the portion of the "Cancun Agreements" dealing with the extension of the Kyoto Protocol beyond its previously-set 2008-2012 term, the delegates mainly agreed to keep talking and to try to come up with a framework in time to avoid a "gap between the first and second commitment periods." Considering that last year's session in Copenhagen was widely viewed before its start as the last, best chance to accomplish that goal based on the timeline set in Bali two years prior, the end of 2011 looks pretty late in the game to deliver on that. Moreover, while Cancun was able to get by on low expectations, Durban will be unable to repeat that trick and avoid the kind of set-up that helped doom the Copenhagen talks.

The chasm that remains to be bridged doesn't seem to have changed much: the developing countries still insist on binding emissions reduction targets from the developed countries, to which the UN process attributes the majority of emissions under the "principle of historical responsibility, their emissions debt and addressing the needs of developing countries", but won't commit to binding targets themselves. (I've discussed this notion of "emissions debt" previously.) But while the US has signed up for voluntary emissions reductions under the Copenhagen Accord, it won't agree to binding cuts unless the world's largest emitter, China, also does. And all China appears willing to agree to, based on its Copenhagen commitments, is the sort of productivity-based reductions that the rest of the developed world rejected when the US advanced this idea for managing our emissions in the first term of the Bush administration. Even if China succeeds in cutting its emissions per GDP by 40-45% while its economy continues on its present growth trend, its overall emissions would still increase in absolute terms. Japan and some other Kyoto signatories are understandably reluctant to sign up for deeper cuts themselves, unless the world's two biggest emitters commit to sharing their pain.

And this is where the timing of any substantive Kyoto extension hits the wall of US politics. If the administration wasn't able to pass cap and trade legislation in the last Congressional session, when its party had an effective majority of 60 seats in the US Senate in 2009 and 59 in 2010, the prospect of ratifying a climate treaty with a majority of just 53 next year--including one who campaigned vocally against cap and trade--is nearly non-existent. The administration is struggling just to get the new strategic arms treaty with Russia ratified in the Lame Duck session--a treaty with solid bi-partisan endorsements from the foreign policy leadership of past administrations. The likely reception for a new climate treaty would be much less favorable than that until at least 2013 and probably beyond, in light of the ratio of seats up for reelection in 2012.

Unless I'm missing something major, without the US and China on board for binding cuts Japan and others won't agree to deeper reductions in the next round of Kyoto. That doesn't mean that the Durban Climate Conference won't cobble together an eleventh-hour agreement that looks like an extension of Kyoto, in order to avoid an irreparable rupture between the developed and developing world parties to the talks. The subtext for that is already in place in the Cancun outcome. However, it seems highly unlikely that such a document would actually do what Kyoto was intended to do. As a result, the UN process seems to be consigned to focusing on the secondary areas that progressed in Cancun, relating to funding for adaptation and technology transfer, and emissions reductions from sectors like land-use changes and forestry. With the economies of the developed world looking as weak as they do, and with domestic expenditure cuts in the EU having generated noisy and sometimes violent protests, coming up with the funding for those efforts looks more than challenging enough for now.

Friday, December 10, 2010

The first production-model Nissan Leaf electric vehicle is scheduled to be delivered to a customer in the San Francisco Bay Area tomorrow. I know if I were on the receiving end, I'd be as excited as a kid on Christmas morning, particularly in a place where having the first Leaf will score its owner many green points. However, if the assessment by MIT's Technology Review of Nissan's choices concerning the temperature control of the Leaf's battery pack is accurate, then it's probably just as well that the first one is going to a location with such a benevolent climate, instead of the Midwest, upstate New York, or the desert Southwest. Batteries are sensitive to external temperature, in terms of both performance and longevity, and Nissan appears to be betting that making the battery simpler to replace is a higher priority than optimizing its condition at all times, as GM has done for the battery pack in the Chevrolet Volt.

It's easy to forget that batteries are fundamentally chemical, rather than just electronic devices. The chemical reactions in a battery absorb or release heat during the charge/discharge cycle, and the capacity of the battery's environment to accommodate those heat flows can affect these reactions. For a battery pack storing and delivering as much energy as required to run a car, these interactions are significant, and early adopters of EVs are already learning that the range of EVs becomes more limited in hot or cold weather. It's not as clear that they understand the degree to which extreme temperatures can degrade battery life. The economics of an EV could look very different if a battery pack only lasted six or seven years, instead of ten.

As the article explains, GM chose a liquid cooling system for the battery pack in its Volt range-extended EV. This system cools or heats all of the battery's cells, as necessary, and sometimes draws power for this purpose even when the vehicle is parked, as I learned when I test-drove one with the Volt's Vehicle Line Director last winter. According to him, GM's design team knew it had to go to extraordinary lengths to ensure the battery would perform reliably and last the expected ten years or 150,000 miles. Nissan appears to have taken a different path to battery management, providing a cooling fan for the battery pack and an optional battery heater--an option reportedly not available on the first Leafs. You don't have to be an expert in heat transfer to guess that air won't move heat around the battery pack's cells as well as liquid can, and that as a result, at least part of the Leaf's battery could potentially be exposed to more heat and cold--and possibly suffer more performance impact from them--than the Volt's.

That trade-off might reflect a different vision for how the battery will be used. Nissan (with its alliance partner Renault) is the main carmaker working with Better Place, Shai Agassi's EV battery recharging-and-exchanging start-up. A battery pack with only electrical connections to the car will be much easier and neater to swap in and out than one with liquid hoses running to a radiator and heater. This situation wouldn't even be a consideration for the Volt, which has an onboard generator to take over when the battery's charge falls too low. But for battery-only EVs, battery-swapping is as close as they can get to replicating the convenience of refueling a gasoline or diesel car in a few minutes. If EVs catch on via a business model like Better Place's, in which consumers routinely exchange their flat batteries for fully-charged ones (and might not even own the battery pack, but instead rent it by the month or the mile) any shortcomings from Nissan's less robust battery-conditioning strategy would fall on someone other than the consumer, as a statistical cost of doing business.

From my perspective this is just one of the uncertainties concerning the operation and consumer acceptance of EVs about which we'll learn more as their numbers climb from the low thousands to the hundreds of thousands and millions. However, I find it interesting that few journalists have picked up on an issue that could have far more impact on the EV ownership experience than the tempest in a teapot that some stirred up when they found out that the Volt's wheels are occasionally driven partly by the engine-generator, rather than entirely electrically. If I were buying one of these cars, I'd be a lot more interested in how far its expensive battery pack will carry me and how long it will last, than in whether the car is truly a range-extended EV or just a plug-in hybrid.

Wednesday, December 08, 2010

As I noted in last Wednesday's posting, one of the questions that came up in a webinar on shale gas in which I participated concerned the climate consequences of higher recent estimates of methane leakage from US natural gas systems. In reading further comments and blog postings on this subject, I was surprised to see assertions that went beyond drawing attention to the importance of the leakage of a high-value, high global-warming-impact gas, to suggest that the apparent rate of leakage renders the lifecycle emissions from natural gas as bad as those from coal, or worse. If that were true, it would have significant implications not only for the development of shale and other natural gas resources, but also for our entire emissions reduction strategy. From what I can tell, however, such claims have not been substantiated by current studies.

Several comments I received in email or on the posting pointed to the work of Professor Robert Howarth of Cornell University, and specifically to a press release describing a paper he has apparently submitted addressing the climate impact of methane leaks from shale gas production, transportation and storage. Until the details of the paper are available, the information provided in the press release simply doesn't stand on its own or merit further analysis. In the meantime, a recent EPA report evaluating greenhouse gas emissions from the oil and gas industry identifies significantly higher estimates for methane emissions from natural gas systems than those incorporated into that agency's most recent US Greenhouse Gas Inventory. I became aware of the EPA report in the course of reading one of the blog postings I alluded to above.

The EPA estimated the total CO2-equivalent methane leakage from the production, processing, transportation, storage and distribution of natural gas in the US in 2006 at 261 million tons per year. That amounts to more than 4% of total net US emissions for that year, so it is hardly insignificant. It's also about 2.5 times the figure reported in the agency's latest GHG inventory. Converting that quantity back into natural gas at normal conditions yields 656 billion cubic feet of gas, or 3.4% of marketed US natural gas production in 2006. That's a lot higher than typical leakage estimates of less than 1%, as David Lewis notes in his blog. The question is whether this higher level of leaks, or some even higher notional level of leaks proposed by other critics, would be sufficient to make the emissions from gas worse than those from coal.

To understand why that might even be possible, you have to know something about the relative strength of different greenhouse gases (GHGs). While much of the public's attention has been focused on CO2, the most prevalent man-made GHG, other gases have dozens or hundreds of times the impact on climate, per ton. Because of the way it decays in the atmosphere, methane's global warming potential (GWP) starts high and diminishes over longer time spans. Most reports, including the EPA's, use a 100-year GWP estimate indicating methane is around 21 times worse than CO2.

However, it's not correct to infer from that that upstream leaks of 3.4% of all natural gas must therefore inflate the lifecycle emissions of the gas we consume by 21 times 3.4%, or 71%. That's because a ton of methane doesn't convert to a ton of CO2 when burned; it yields 2.75 tons, as a result of basic high school chemistry:

CH4 + 2O2 --> CO2 + 2H20

So for each ton of natural gas, it's roughly 7.6 time worse for it to be vented or leaked than burned, after adjusting methane's standard GWP for the ratio of molecular weights from the above reaction equation. In fact, when I added the EPA's latest methane emissions estimates to their figures for indirect and direct CO2 emissions from natural gas in the GHG inventory, the result was very close to the 26% increase you'd get from multiplying 3.4% by 7.6. As a result, although the emissions advantage of natural gas over coal is less than it would be without such a high rate of leakage, gas still emits 35% less CO2 equivalent per BTU over its lifecycle than coal, on average.

When you consider how natural gas actually competes with coal, its effective emissions advantage should be larger than that. Even after accounting for upstream emissions (including leakage) that add 30% to its CO2 emissions from combustion, an efficient combined-cycle power plant still generates electricity with emissions per kilowatt-hour that are more than 40% lower than those from a highly-efficient coal plant. That's because the combined cycle turbine converts more than half the BTUs in its fuel into electricity, while the coal plant converts less than 40% of coal's BTUs into power. Fewer BTUs for the same output results in fewer emissions.

I don't claim my back-of-the-envelope analysis is definitive, but it certainly doesn't support the notion that gas is worse than coal. Barring conclusive evidence of a much higher level of upstream natural gas leakage than indicated by the EPA's latest work on the subject, natural gas--even with existing infrastructure--could reduce the emissions associated with coal use in power generation by at least a third, and by much more than that depending on the specific generating facilities involved. At the same time, that shouldn't be read as excusing avoidable leaks of gas. If that 3% figure is accurate or low, then several billion dollars worth of gas--even at today's depressed prices--is escaping into the atmosphere rather than being captured and turned into useful energy by gas customers. That sounds like the epitome of low-hanging fruit to me.

Monday, December 06, 2010

This morning I ran across a news item indicating that Dow Chemical was installing a biomass cogeneration unit at its facility in Aratu, Brazil to provide process steam with minimal greenhouse gas emissions. It's a good example of another way to convert biomass into energy that hasn't attracted nearly as much interest as advanced biofuels have. That's somewhat surprising, since biomass power shares most of the logistical limitations but few of the technical challenges that have made the production of biofuel from non-food biomass so difficult. Perhaps the relative neglect of biomass power results more from motivation than outcomes.

I'm sure I paid more attention to this story because of Dow's choice of eucalyptus as the biomass source. I grew up under the spreading limbs of a giant eucalyptus tree in California--limbs that periodically fell off in storms, including a 9-ton monster that practically cut our house in half. In the years before that tree was finally cut down I raked up enormous quantities of the eucalyptus leaves and nuts that bombarded our yard. It would be fair to say that I developed a strong distaste for the species, at least for the ornamental and wind-break purposes for which many Californians had chosen this Australian import. However, many of these same features, including its fast growth and dense, oily wood, seem to be good attributes for biomass supply.

As noted in a recent Wall St. Journal article, the Achilles heel of biomass power is logistics. The lower the energy density of the biomass, relative to the fossil fuels it is intended to replace, the closer the source must be to the facility where it will be used, before transportation erodes any cost benefits, even after considering emissions reductions. Wood chips provide about 2/3 as much energy per pound as bituminous coal, but they can take up more than six times as much volume, unless they are first dried and turned into pellets. As is the case for cellulosic biofuels, these supply-chain considerations limit the scale of biomass power application and impose an additional constraint of sustainability: It doesn't pay to build a biomass power plant (or a cellulosic biofuel plant) unless you can be sure of a long-term supply of the raw material. The Journal article included examples of projects that paid a high price for miscalculations in this regard. One strategy for mitigating this limitation is co-firing, which relies on biomass for only a portion of a power plant's fuel needs.

The lower energy density of biomass also makes it essential to extract as much energy as possible from each pound or cubic foot. One of the reasons for the high efficiency of the Brazilian ethanol industry is that many of its mills turn the bagasse, the waste left over after extracting the juice from sugar cane, into process heat and power and need little or no fossil energy. Burning biomass in a high-efficiency combined heat and power application, as the Dow project appears to do--based on the scant information I could find--provides another way to get the most bang for the biomass buck.

That brings us back to motivation. One of the main justifications for the pursuit of cellulosic biofuels is that we have relatively few practical, cost-effective alternative fuels that could replace more than a small fraction of our petroleum use. On the other hand, we have many ways to generate electricity, including more than a few that emit little or no greenhouse gas, one of the main benefits of biomass power--though this point is not without controversy. However, I can't help wondering whether in the long run the best way to turn non-food biomass into energy for vehicles is to turn it into electricity first, rather than working so hard to break down plant structures that have evolved over millions of years to resist easy conversion into chemical energy. Resolving that dilemma depends on a lot more than engineering considerations, however, since we still don't know much about how consumer preferences will play into it. In the meantime, projects like Dow's provide another option for reducing emissions from facilities that must meet increasingly stringent sustainability criteria.

Friday, December 03, 2010

Time is running out for the ethanol blenders credit and the matching ethanol import tariff, which at least one industry publication suggests are likely to survive, but at "sharply reduced rates." Although I'm among those who suspect that the blenders credit probably benefits consumers more than ethanol producers, as long as the national Renewable Fuel Standard is binding on blenders, it seems fortunate for the US ethanol industry that this situation is playing out when crude and gasoline prices have risen to levels we haven't seen since spring, and could go higher if current economic indicators hold up.

The US benchmark futures price for crude oil is suddenly flirting with $90/bbl again, and UK Brent crude, a better gauge of world oil prices whenever WTI inventories at Cushing, OK are this high, has already surpassed that mark. Even if oil's move is at least partly the result of recent currency fluctuations, it is supported by fundamentals in the form of gasoline and distillate inventories that for the first time in months are back within their normal seasonal ranges. Crack spreads, an indicator of refining margins, look strong, reflecting solid demand. All of that suggests that if crude prices move higher, increases will be passed on in product prices, rather than being absorbed partly by refiners. That doesn't sound like good news for motorists, but how could it help compensate the ethanol industry for the potential loss of some or all of the $0.45 /gal. blenders credit?

It helps in two ways. First, by pushing wholesale gasoline prices above those for prompt ethanol even without factoring in the credit, this gives refiners more incentive to add as much ethanol to gasoline as they can, to increase their profit margins. That should put positive pressure on ethanol prices, even as blenders approach the 10% "blend wall" that the recent EPA decision on E15 hasn't yet affected. That opens up headroom for ethanol producers who have recently seen their margins, or "crush spreads", squeezed by strong corn prices. And it's especially crucial for those producers who only recently emerged from Chapter 11 protection after a protracted margin squeeze in late 2008 though mid-2009. This is an industry that spent the last five years in a frenzy of capacity building, and that only escaped creating a severe and persistent glut of ethanol because some of the marginal operators couldn't afford to run their plants. If gasoline prices fell while corn prices remain high, losing the blenders credit could put a number of plants back into bankruptcy; rising gasoline prices constitute a lucky break.

It's anyone's guess whether the present configuration of markets will remain in place long enough to ease the ethanol industry through the transition it faces after December 31, if the Congress cuts the blenders credit and tariff or allows them to lapse. After all, Europe has just dodged another bullet with Ireland, and the Euro could come under renewed threat from Portugal, Spain or Italy at any time. If recent shopping results are any indication, the US economy is looking healthier, although joblessness remains high and unemployment benefits for millions are set to end before the holiday bills come due. If oil prices swooned in the next few weeks, consumers might be relieved, but ethanol producers would see it as another lump of coal in their stocking.

Wednesday, December 01, 2010

Yesterday I participated in a webinar examining the sustainability aspects of the shale gas revolution. The online audience asked good, probing questions, and if there was a theme to them, it seemed to be that somehow the sudden abundance of natural gas resulting from a novel combination of shale-exploitation technologies--as well as the technologies themselves--must at a minimum be considered a mixed blessing, if not actually too bitter a pill to swallow, because of its perceived shortcomings and the potential threat it poses to other, favored energy technologies. I find that simultaneously understandable and unfortunate.

I came of age just as US attitudes concerning energy shifted from the assumption of perpetual abundance to perennial insecurity and periodic scarcity. Energy security has been a consistent theme of public discourse for my entire adult life, varying only in intensity as we lurched from crisis to crisis with long respites in between. If the shale gas revolution had arrived thirty years earlier, I'm confident it would have been embraced as a national windfall--a jackpot lottery win. After all, we're talking about a newly accessible resource that is equivalent to finding an Iraq's worth of hydrocarbons under our feet, not deep offshore or in some distant country. Yet despite boosting US gas production to levels unseen since the early 1970s and resetting gas prices to pre-2000 levels, after adjusting for inflation, the reception of shale gas has been decidedly mixed, as witnessed by yesterday's vote by the New York legislature to impose a six-month moratorium on gas drilling in a state overlying a portion of one of the largest gas reservoirs in the world.

Shale gas isn't the silver bullet for our energy and emissions problems, but it can contribute significantly towards alleviating both. Combined-cycle power plants burning gas emit only about 45% as much greenhouse gases as best-in-class coal-fired power plants, and comparisons to the oldest, least-efficient US coal plants are even more favorable. At current gas prices, which are mainly the result of the shale gas boom, the resulting power is cheaper than from any renewable source without substantial subsidies, and than most even after subsidies. In the last several years gas-fired power plants have taken market share from coal equivalent to the entire output of all US wind farms, and there's no wait for scaling-up.

At the same time, the concerns about shale gas reflected in some of yesterday's questions are entirely understandable, particularly in an era dominated by low trust in all institutions. For example, is it possible that unreported natural gas leaks are releasing enough methane, which is a strong greenhouse gas, to offset all the emissions benefits from gas-fired generation? Perhaps, even though the gas leaks identified in a new GAO report amount to just 0.2% of US marketed production, and thus equate to only about 6% of the CO2-equivalent emissions associated with US gas consumption. But as I noted in the webinar, even if the leaks are in fact much larger they are controllable; they are not an inherent feature of shale gas production in the way coal's CO2 emissions are inherent in coal combustion.

Concerns about water consumption and safety hit even closer to home. Having reviewed the list of fracking chemicals on Halliburton's website, I wouldn't want them in my drinking water, either, any more than I'd want my family consuming any of the various household chemicals under our kitchen sink or elsewhere in our home. However, there's nothing about the process of hydraulically fracturing shale strata thousands of feet deeper underground than the deepest aquifers that puts our drinking water at any greater risk than many routine industrial or agricultural operations. As a technology fracking is neither newer nor riskier than many other things to which we don't give the slightest thought. Much of the attention it has gained is the result of its application in unaccustomed places--a reaction shared by wind turbines, utility-scale solar plants, and long-distance transmission lines.

The biggest uncertainties associated with shale gas don't concern the size of the resource or our ability to extract it safely, but whether we will decide to allow this to be done on a scale that would make a meaningful difference in our energy and emissions balances, or under such tight restrictions that we will forgo its game-changing potential. Like anything, shale gas drilling and fracking must be done responsibly, in accordance with state and local regulations and to industry standards that are constantly improving. Post-Deepwater Horizon, that's a much tougher sell, but it doesn't make it any less important. Shale gas isn't perfect energy, not because of any unique imperfections, but because there is no perfect energy source. It requires mature, reasonable assessments of its risks that don't assume that there is.